This paper provides an overview of the different point-of-regulation options for covering greenhouse gas emissionsfrom natural gas under a cap-and-trade program. The paper assesses the percentage of emissions covered under the different options and the type and number of entities and facilities regulated.

Overview

Greenhouse gas (GHG) emissions associated with natural gas make up nearly 18 percent of total U.S. GHG emissions.1 Regulation of GHG emissions from the natural gas sector under a cap-and-trade program presents challenges different from those associated with coal or petroleum for several reasons:

End users of natural gas number in the millions and include not only large industrial facilities and electricity generators, but also a wide variety of smaller users in the commercial and residential sectors.

Although the principal GHG concern for the sector is carbon dioxide (CO2) emissions from natural gas combustion, the sector also generates non-energy CO2emissions and fugitive emissions of methane (CH4), which are difficult to measure and monitor.2

There are a number of different types of entities in the natural gas supply chain from production to end use making it difficult to apply the standard upstream vs. downstream dichotomy traditionally used to think about the point of regulation for petroleum and coal under cap-and-trade programs.

Both physical possession and, in many cases, ownership of the natural gas commodity change multiple times within the value chain as natural gas moves from producers to end-use consumers.

These factors have made the treatment of natural gas a challenging issue in the design of a federal economy-wide GHG cap-and-trade program.3 Bills introduced in Congress have reflected a range of different approaches.4 Even different versions of the Lieberman-Warner bill (S. 2191) incorporated different approaches.

A particularly important design issue is whether to directly regulate GHG emitters or to regulate firms for the embedded emissions of the fossil fuels that they produce, process, transport, or distribute.5 For fossil fuels like natural gas, embedded emissions are the GHG emissions that will ultimately be emitted once the fuel is combusted (see box below for a discussion of the direct vs. embedded emissions and upstream vs. downstream points of regulation). A point of regulation for natural gas coverage under cap and trade that regulates embedded emissions would cover emissions by end users indirectly through the regulation of entities/facilities that produce, process, transport, or distribute natural gas.6 Under a cap-and-trade program, these entities/ facilities would be required to acquire and retire emission allowances equal to their embedded emissions—i.e. the CO2emissions from combustion of the natural gas that these entities/facilities produce, process, transport, or distribute. In theory, entities regulated for their embedded emissions would pass the cost of allowances on to consumers of natural gas thus providing the same economic incentive for emission reductions on the part of emitters as would a cap-and-trade program that regulated direct emissions.7

The reason for interest in regulating embedded emissions is that it may be possible to, in effect, cover the direct emissions of many diverse emission sources by regulating the embedded emissions of relatively few entities that produce, process, transport, or deliver fossil fuels. For example, GHG emissions from many millions of motor vehicles could be covered under cap and trade via regulation of the embedded emissions of approximately 150 U.S. oil refiners plus some importers of fuel. That said, there is concern as to whether in practice the price signal established by regulating embedded emissions is an efficient or effective way to ensure GHG reductions from end users.

In considering the point-of-regulation options, one must consider what percentage of GHG emissions from the natural gas sector each option would cover and how many and what kinds of entities/facilities would need to be regulated. The latter question is important from the perspective of allowing for the accurate measurement of direct emissions by regulated entities/facilities or embedded emissions from natural gas produced, processed, transported, or distributed by regulated entitities/facilities. Moreover, all else equal, a cap-and-trade program that limits the number of entities/facilities that must be monitored for compliance limits the associated administrative costs borne by government and industry. One should also consider the efficiency with which different point-of-regulation options achieve emission reductions because of differences in compliance options and responsiveness to price signals among entities at different points along the natural gas value chain. This last question is the subject of a forthcoming paper.

The following sections of this paper review the emissions profile of the natural gas sector, identify the key entities and associated facilities in the natural gas supply chain, provide an estimate of the emissions coverage and number of entities and facilities regulated under various point-of-regulation options, and provide a summary of the analysis.

About the Author

Joel Bluestein is Senior Vice President of ICF International and is a nationally recognized expert on the impacts of environmental and energy regulation with over 30 years of experience in the energy and environmental arenas. Prior to 2007, he was President of Energy and Environmental Analysis, Inc., now an ICF International company, which was nationally known for its analysis of natural gas supply, transportation, and market issues and provided strategic planning and regulatory support to all segments of the natural gas industry.

Mr. Bluestein has been directly involved in the development of emission trading programs and participates in the national debate on new environmental policies and their energy implications. He has testified before the Senate Environment and Public Works Committee on natural gas supply issues and their implications for multi-pollutant regulation of the electric generating sector. His work has included technology and market assessments, R&D planning, energy conservation project analysis, and long-term energy demand forecasting. He holds a degree in Mechanical Engineering from the Massachusetts Institute of Technology and is a registered Professional Engineer.